Field of the Invention
This invention relates to integrated processes and systems for production of asphalt, high quality petroleum green coke, and liquid and gas coking unit products.
Description of Related Art
Crude oils contain heteroatomic molecules, including polyaromatic molecules, with heteroatomic constituents such as sulfur, nitrogen, nickel, vanadium and others in quantities that impact the refinery processing of the crude oils fractions. Light crude oils or condensates have sulfur concentrations as low as 0.01 percent by weight (W %), in contrast, heavy crude oils and heavy petroleum fractions have sulfur concentrations as high as 5-6 W %. Similarly, the nitrogen content of crude oils is in the range 0.001-1.0 W %. The heteroatom contents of various Saudi Arabian crude oils are given in Table 1. As seen, the heteroatom content of the crude oils within the same family increases with decreasing API gravity on increasing heaviness. The heteroatom content of the crude oil fractions also increases with increasing boiling point (Table 2).
TABLE 1PropertyASLAELALAMAHGravity, °51.439.533.031.127.6Sulfur, W %0.051.071.832.422.94Nitrogen, ppmw70446106414171651RCR, W %0.511.723.875.277.62Ni + V, ppmw<0.12.92134.067ASL—Arab Super LightAEL—Arab Extra LightAL—Arab LightAM—Arab MediumAH—Arab Heavy
TABLE 2Fractions, ° C.Sulfur W %Nitrogen ppmwC5-900.01 93-1600.03160-2040.06204-2600.34260-3151.11315-3702.00253370-4302.06412430-4822.65848482-5703.091337
Contaminants (poisonous compounds) such as sulfur, nitrogen, poly-nuclear aromatics in the crude oil fractions impact the downstream processes including hydrotreating, hydrocracking and fluid catalytic cracking (FCC). The contaminants are present in the crude oil fractions in varying structures and concentrations. These impurities must be removed during the refining to meet the environmental regulations for the final products (e.g., gasoline, diesel, fuel oil) or for the intermediate refining streams that need to be processed for further upgrading such as reforming isomerization. Contaminants such as nitrogen, sulfur and heavy metals are known to deactivate or poison catalysts.
In conventional refining schemes, crude oil is first in an atmospheric column to separate sour gas and light hydrocarbons including methane, ethane, propane, butanes and hydrogen sulfide, naphtha (36-180° C.), kerosene (180-240° C.), gas oil (240-370° C.) and atmospheric residue bottoms which include hydrocarbons boiling above 370° C.
The atmospheric residue from the atmospheric distillation column is either used as fuel oil or sent to a vacuum distillation unit, depending on the configuration of the refinery. In configurations in which the bottoms are further distilled in a vacuum distillation column, products obtained include vacuum gas oil having hydrocarbons boiling in the range 370-520° C. and vacuum residue having hydrocarbons boiling above 520° C.
As the boiling point of the petroleum fractions increases, the quality of oil decreases and negatively impacts the downstream processing units. Table 3 and Table 4 provide quality of atmospheric (boiling above 370° C.) and vacuum residual (boiling above 520° C.) oils derived from various crude sources. It is clearly shown in these tables that the atmospheric or vacuum residues are highly contaminated with heteroatoms and have high Condranson carbon residue content and the quality deteriorates with decreasing API Gravity.
TABLE 3APISulfur,Ni + V,CCR,SourcenameGravity, °W %ppmwW %Middle EastArabian Light16.803.14550.007.60Middle EastArabian Heavy12.704.30125.0013.20South AsiaMina26.400.1516.004.20South AsiaDuri17.500.2217.009.30ChinaShengli18.701.2319.008.60ChinaTaching25.100.134.004.00Latin AmericaMaya8.304.82494.0017.40Latin AmericaIsthmus13.902.9653.008.20
TABLE 4APISulfur,Ni + V,CCR,sourcenameGravity, °W %ppmwW %Middle EastArabian Light6.904.34141.0020.30Middle EastArabian Heavy3.006.00269.0027.70South AsiaMina17.300.1944.0010.40South AsiaDuri13.000.2532.0015.20ChinaShengli11.701.6628.0016.40ChinaTaching18.700.189.009.50Latin AmericaMaya−0.105.98835.0029.60Latin AmericaIsthmus4.004.09143.0021.10
Naphtha, kerosene and gas oil streams from crude oils or other natural sources such as shale oils, bitumens and tar sands, are treated to remove the contaminants mainly sulfur, whose quantity exceeds the specifications. Hydrotreating is the most common refining technology to remove these contaminants (poisonous compounds for other processes/catalysts or to meet final fuel specifications). Vacuum gas oil is processed in a hydrocracking unit to produce gasoline and diesel or in an FCC unit to produce mainly gasoline, and LCO and HCO as by-products. The former of which is either used as a blending component in a diesel pool or fuel oil, while the latter is sent directly to the fuel oil pool.
Heavier fractions from the atmospheric and vacuum distillation units can contain asphaltenes. Asphaltenes are solid in nature and comprise polynuclear aromatics, smaller aromatics and resin molecules. The chemical structures of asphaltenes are complex and include polynuclear hydrocarbons having molecular weights up to 20,000 joined by alkyl chains. Asphaltenes also include nitrogen, sulfur, oxygen and metals, i.e., nickel, vanadium. They are present in crude oils and heavy fractions in varying quantities. Asphaltenes exist in small quantities in light crude oils, or not at all in all condensates or lighter fractions. However, they are present in relatively large quantities in heavy crude oils and petroleum fractions. Asphaltenes have been defined as the component of a heavy crude oil fraction that is precipitated by addition of a low-boiling paraffin solvent, or paraffin naphtha, such as normal pentane, and is soluble in carbon disulfide and benzene. In certain methods their concentrations are defined as the amount of asphaltenes precipitated by addition of an n-paraffin solvent to the feedstock, e.g., as prescribed in the Institute of Petroleum Method IP-143. The heavy fraction can contain asphaltenes when it is derived from carbonaceous sources such as petroleum, coal or oil shale. There is a close relationship between asphaltenes, resins and high molecular weight polycyclic hydrocarbons. Asphaltenes are hypothesized to be formed by the oxidation of natural resins. The hydrogenation of asphaltic compounds containing resins and asphaltenes produces heavy hydrocarbon oils, i.e., resins and asphaltenes are hydrogenated into polycyclic aromatic or hydroaromatic hydrocarbons. They differ from polycyclic aromatic hydrocarbons by the presence of oxygen and sulfur in varied amounts.
Upon heating above about 300-400° C., asphaltenes generally do not melt but rather decompose, forming carbon and volatile products. They react with sulfuric acid to form sulfonic acids, as might be expected on the basis of the polyaromatic structure of these components. Flocs and aggregates of asphaltenes will result from the addition of non-polar solvents, e.g., paraffinic solvents, to crude oil and other heavy hydrocarbon oil feedstocks.
Therefore, it is clear that significant measures must be taken during processing of crude oils and heavy fractions to deal with asphaltenes. Failure to do so interferes with subsequent refining operations.
There are several processing options for the vacuum residue fraction, including hydroprocessing, coking, visbreaking, gasification and solvent deasphalting.
In additional configurations, vacuum residue can be treated in an asphalt unit to produce asphalt by air oxidation. Asphalt oxidation is a process in which air is bubbled through the feedstock or pitch in an oxidizer column vessel to oxidize sulfur-containing compounds. It is a non-catalytic process to shift the sulfur molecules from the oil phase to the asphalt phase.
In some refining configurations, the vacuum residue can be processed in a solvent deasphalting unit to separate the solvent soluble (deasphalted oil) and insoluble oil (asphaltenes) fractions.
Solvent deasphalting is an asphalt separation process in which residue is separated by polarity, instead of by boiling point, as in the vacuum distillation process. The solvent deasphalting process produces a low contaminant deasphalted oil (DAO). These fractions can then be further processed in conventional conversion units such as an FCC unit or hydrocracking unit. The solvent deasphalting process is usually carried out with paraffin C3-C7 solvents at or below critical conditions.
Further material regarding solvent deasphalting can be found in U.S. Pat. Nos. 4,816,140; 4,810,367; 4,747,936; 4,572,781; 4,502,944:4,411,790; 4,239,616; 4,305,814; 4,290,880; 4,482,453 and 4,663,028, all of which are incorporated herein by reference.
Deasphalted oil contains a high concentration of contaminants such as sulfur, nitrogen and carbon residue which is an indicator of the coke forming properties of heavy hydrocarbons and defined as micro-carbon residue (MCR) or Conradson carbon residue (CCR) or Ramsbottom carbon residue (RCR). MCR, RCR, CCR are determined by ASTM Methods D-4530, D-524 and D-189, respectively. In these tests, the residue remaining after a specified period of evaporation and pyrolysis is expressed as a percentage of the original sample. For example, deasphalted oil obtained from vacuum residue of an Arabian crude oil contains 4.4 W % of sulfur, 2,700 ppmw of nitrogen, and 11 W % of MCR. In another example, a deasphalted oil of Far East origin contains 0.14 W % sulfur, 2,500 ppmw of nitrogen, and 5.5 W % of CCR. These high levels of contaminants, and particularly nitrogen, in the deasphalted oil limit conversion in hydrocracking or FCC units. The adverse effects of nitrogen and micro-carbon residue in FCC operations have been reported to be as follows: 0.4-0.6 W % higher coke yield, 4-6 V % less gasoline yield and 5-8 V % less conversion per 1000 ppmw of nitrogen. (See Sok Yui et al., Oil and Gas Journal, Jan. 19, 1998.) Similarly, coke yield is 0.33-0.6 W % more for each one W % of MCR in the feedstock. In hydrocracking operations, the catalyst deactivation is a function of the feedstock nitrogen and MCR content. The catalyst deactivation is about 3-5° C. per 1000 ppmw of nitrogen and 2-4° C. for each one W % of MCR.
It has been established that organic nitrogen is the most detrimental catalyst poison present in the hydrocarbon streams from the sources identified above. Organic nitrogen compounds poison the active catalytic sites resulting in catalyst deactivation, which in turn reduces catalyst cycle process length, catalyst lifetime, product yields, and product quality, and also increases the severity of operating conditions and the associated cost of plant construction and operations. Removing nitrogen, sulfur, metals and other contaminants that poison catalysts will improve refining operations and will have the advantage of permitting refiners to process more and/or heavier feedstocks.
In coking processes, heavy feeds are thermally cracked to produce coke, gas and liquid product streams of varying boiling ranges. Coke is generally treated as a low value by-product. It is removed from the units and can be recovered for various uses depending on its quality.
The use of heavy crude oils having high metals and sulfur content as an initial feed is of interest due to its lower market value. Traditional coking processes using these feeds produce coke which has substantial sulfur and metal content. The goal of minimizing air pollution is a further incentive for treating residuum in a coking unit since the gases and liquids produced contain sulfur in a form that can be relatively easily removed.
While individual and discrete asphalt oxidation, solvent deasphalting and coking operations processes are well developed and suitable for their intended purposes, there remains a need in the art for more economical and efficient processes for obtaining product from heavy feeds such as atmospheric and/or vacuum residues containing asphaltenes, N, S and metal contaminants.